A necessary and integral part of a fluid catalytic cracking reactor involves the regenerator wherein the spent catalyst has its activity restored. Regeneration of spent catalyst is generally effected after separation of the spent catalyst from the reaction products. The spent catalyst is removed from the reaction zone and contacted in a stripping zone with a stripping medium, usually steam, to remove vaporized and entrained and/or occluded hydrocarbons from the catalyst. From the stripping zone, a stripped catalyst is passed into a regeneration zone wherein the stripped spent catalyst is regenerated by burning coke deposits therefrom with an oxygen-containing gas, usually air. The resulting hot regenerated catalyst from the egeneration zone is then recycled to the reaction zone in contact with additional hydrocarbon feed. When the hydrocarbon feed to the fluid catalytic cracking reactor riser contains sulfur, oxides of sulfur report in the flue gas from the regenerator, creating a noxious gas stream unless the feed is low in sulfur. A similar problem of sulfur oxide emissions resulting from regeneration of spent solid contact material by burning occurs in the operation of fluid cokers or selective vaporization processes of the type described in U.S. Pat. No. 4,263,128 to Bartholic, the entire disclosure of which is incorporated herein by reference. Sulfur oxide emissions in flue gases also occur in operation of coal fired boilers or any process in which sulfur-containing fuel is combusted.
Flue gas sulfur removal units have been expensive to build and are often plagued with operating and/or by-product disposal problems. Flue gas sulfur removal units fall into three general categories: wet systems, once through dry systems, and regenerable systems.
Wet flue gas sulfur removal systems consume large quantities of water, require stack gas reheat, create slurries that are dewatered in crystallizers or settling ponds, and are built employing expensive metallurgy to combat corrosion. Once through dry systems generate large quantities of solids that must be disposed. The solids handling facilities are a frequent source of problems. Regenerable dry systems are often expensive to build because they employ swing adsorbers. While one adsorber train is capturing sulfur, the other is undergoing regeneration. The valving required to effect the adsorber changes must be able to withstand the temperature and solids content of the flue gas. Solids present in the flue gas stream coat the adsorbent if it is stationary and dilute the adsorbent if it is fluidized. The net result is reduced SOx removal efficiency. Some of the regenerable systems require high purity desorption gas.
In attempts to reduce sulfur oxide (SOx) emissions from FCC units, SOx transfer additives have been injected into the circulating catalyst inventory. Similar technology has been suggested for operating selective vaporization units. See U.S. Pat. No. 4,325,815 to Bartholic.
The SOx transfer additives are fluidizable particles composed of material capable of reacting with an oxide of sulfur in an oxidizing atmosphere or an environment which is not of substantial reducing nature to form solid compounds capable of reduction in the reducing atmosphere of the FCC reactor to yield H.sub.2 S. Upon such reduction, the sulfur leaves the reactor as gaseous H.sub.2 S and organic compounds of sulfur resulting from the cracking reaction. Since these sulfur compounds are detrimental to the quality of motor gasoline and fuel gas by-products, the catalytic cracker is followed by downstream treating facilities for removal of sulfur compounds. Thus the gaseous fractions of cracked product may be scrubbed with an amine solution to absorb H.sub.2 S which is then passed to facilities for conversion to elesental sulfur, e.g. a Claus plant. The additional H.sub.2 S added to the cracker product stream by chemical reduction in the reactor of the solid sulfur compounds formed in the regenerator imposes little additional burden on the sulfur recovery facilities. It has been proposed to utilize this transfer concept to remove oxides of sulfur from waste gases other than FCC flue gas by introducing such gases into the regenerator of an FCC unit operated with an inventory of SOx adsorbent and removing the sulfur from the circulating inventory in the FCC riser where a reducing atmosphere exists.
Discussion of a variety of oxides which exhibit the property of combining with SOx and thermodynamic analysis of their behavior in this regard are set out by Lowell et al., SELECTION OF METAL OXIDES FOR REMOVING SOx FROM FLUE GAS, IND. ENG. CHEM. PROCESS DES. DEVELOP., Vol. 10, No.3 at pages 384-390 (1971).
An early attempt to reduce SOx emission from catalytic cracking units, as described in U.S. Pat. No. 3,699,037, involves adding particles of a Group II metal compound, especially calcium or magnesium oxide, to a cracking unit cycle at a rate at least as great as the stoichiometric rate of sulfur deposition on the cracking catalyst, the additive preferably being injected into the regeneration zone in the form of particles greater than 20 microns. Particle size was chosen to assure a relatively long residence time in the unit. In putting the invention into practice, the Group II metal compound is recycled at least in part between the reactor and the regenerator, the remainder leaving the cycle along with catalyst fines entrained in regenerator flue gas. Subsequently it was proposed to incorporate the alkaline earth metal compound in the cracking catalyst particles by impregnation in order to minimize loss of the sulfur acceptor in the regenerator flue gases. See U.S. Pat. No. 3,835,031. This patent apparently recognizes the need for free oxygen for binding SOx with a Group II metal oxide since the equations for the reaction taking place in the regenerator is summarized as follows: EQU MgO+SO.sub.2 +1/2O.sub.2 =MgSO.sub.4
Similar use of reactive alumina either as a discrete fluidizable entities or as a component of catalyst particles is described in U.S. Pat. Nos. 4,071,436; 4,115,250 and 4,115,251. Use of oxidants including platinum or chromium as adjuncts to alumina is suggested in these patents. Similar technology has been suggested for operating selective vaporization units. See U.S. Pat. No. 4,325,815 to Bartholic.
In the prior art techniques aforementioned, emphasis was on reversibly reacting sulfur oxides in the flue gas, and doing so while the gases were still in the regenerator. Since the sulfur loaded particles were carried to the reactor to be converted to gaseous hydrogen sulfide under the reducing atmosphere created by the cracking operation, the agents used to bind and then release sulfur were necessarily limited to those capable of doing so under the constraints of temperature and time imposed by the operation of the reactor and the regenerator.
With units operating with high sulfur feedstock, relatively large amounts of sulfur acceptors having high unit capacity to adsorb SOx are needed to accomplish reductions in sulfur oxide levels. This will result in appreciable dilution of the active catalyst in the cracking reaction cycle whether the sulfur acceptor is a part of the catalyst particles or is present as discrete entities circulated with catalyst inventory. A basic limitation is that conditions of time and temperature for operating cyclic cracking units, especially heat balanced FCC units, are geared to maximizing production of desired products and conditions that will favor this result, are by no means those that are optimum for reversibly reacting sulfur oxides in the regenerator and carrying the sulfur back to the reactor for conversion at least in part to hydrogen sulfide. Such procedures offer promise as means to reduce SOx emissions from refineries but they leave much to be desired. The technique has had limited commercial success, however, because SOx removal activity decreases rapidly with time with presently available SOx transfer agents,
In U.S. Pat. No. 4,448,674 (Bartholic) there is described a system for application of the technique of binding SOx in FCC regenerator gases operated with limited air and producing a flue gas containing substantial amounts of carbon monoxide, i.e. a reducing atmosphere. In such cases, the flue gas temperature is reduced to a level at which ignition of CO is inhibited, air is injected to provide an oxidizing atmosphere and the cooled stream containing carbon monoxide and oxygen is contacted with the regenerated catalyst in a transport line under turbulent condition to promote pick-up of SOx. As described in the patent, the effluent from that contact is passed through a valve and then is sent to a CO boiler to recover the fuel value of CO by combustion at higher temperature. The agent to bind SOx is separated from gases in a precipitator and is not regenerated. To the contrary, regenerable agents are avoided because they will release oxides of sulfur in the CO boiler.
U.S. Pat. No. 4,001,375 (Longo) describes a process for the removal of sulfur oxides from gases by a regenerable sorbent composed of a cerium oxide sorbent such as cerium oxide supported on alumina. Contact of gas with sorbent is in a fixed bed. When the sorbent is loaded to a desired level it is transferred to another fixed bed in which hydrocarbon gas or hydrogen in admixture with "steam or other inert gas" is used to regenerate the sorbent. The patent teaches that during regeneration the desorbed species is initially sulfur dioxide when about 50% of the sulfur is removed, the desorbed species becomes H.sub.2 S. Referring to an example in the patent, it is stated that "the regeneration step is almost instantaneous relative to the slower rate of SO.sub.2 pickup."
U.S. Pat. No. 4,325,811 (Sorrentino) describes a process using a regenerable sulfur oxide adsorbent to control SOx emission of the regenerator of an FCC unit in which a stream of particles including particles of the adsorbent is withdrawn from the regeneration zone and passed to a reducing zone to release adsorbed SOx. The stream of particles is then circulated back to the regeneration zone and recirculated between the reaction and the regeneration zone. In the reducing zone temperatures range from about 590.degree. C. (1094.degree. F.) to about 820.degree. C. (1508.degree. F.). The preferred reducing gas comprises a mixture of steam with hydrogen or hydrocarbon.
Illustrative of other patents relating to regenerable SOx adsorbents adapted for use in FCC units are: U.S. Pat. No. 4,153,534 (Vasalos); U.S. Pat. No. 4,153,535 (Vasalos et al); U.S. Pat. No. 4,071,436 (Blanton); U.S. Pat. No. 4,115,249 (Blanton et al); U.S. Pat. No. 4,166,787 (Blanton et al); U.S. Pat. No. 4,146,463 (Radford et al); U.S. Pat. No. 3,835,031 (Bertolacini et al); Canadian Patent 1,154,735 (Brown et al); U.S. Pat. No. 4,423,091 (Bertolacini et al); U.S. Pat. No. 4,495,304 and U.S. Pat. No. 4,495,305 (Yoo et al); U.S. Pat. No. 4,529,574 (Wang); U.S. Pat. No. 4,459,371 and U.S. Pat. No. 4,428,827 (Hobbs et al); and U.S. Pat. No. 4,381,991 (Bertolacini et al).
A recent publication of Andersson et al, "SOx Adsorption/Desorption Processes on .gamma.-Alumina for SOx Transfer Catalyst," Applied Catalysis, 16 (1985) 49-58, describes thermogravimetric investigations into SOx adsorption/desorption for different conditions purported to simulate FCC operations using .gamma.-alumina as the adsorbent. It is noted, however, that conclusions in the paper regarding desorption of SOx in an FCC riser are based on thermogravimetric desorption tests using alumina that was not coked.
A fluidized bed system for reducing NOx and SOx is described in a publication of Haslbeck et al, "The NOXSO Process Development; an Update," prepared for the Ninth EPA-EPRI Symposium on Flue Gas Desulfurization, June 4-7, 1985. A regenerable adsorbent is used.